Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids. In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements. Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production. Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken. Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.

This paper presents experimental and numerical simulation results of oil recovery from short fractured and unfractured carbonate cores using a high speed centrifuge. The short cores are 1.5-inch in diameter and 1.5-inch long. The experiments are designed to decipher oil recoveries contributions from rock matrix in presence and absence of fractures, with and without surfactant. This research demonstrates that surfactant oil recovery can be a viable enhanced oil recovery process in fractured carbonate reservoirs when fracture distribution and connectivity are favorable. These carefully designed experiments improve our understanding of how oil mobilization can be enhanced in fractured carbonate rocks and how the process can be modeled and solved numerically. Three cores were selected from a Middle East carbonate reservoir, saturated with field brine, displaced with a 9-centipoise field crude, and aged to promote oil-wetness. Three different core designs were used in these experiments. One of the cores was fractured along the vertical axis and sealed with epoxy resin on the outer vertical surface. The second core was fractured and sealed on all outer surfaces except for the fracture opening. The third core was unfractured and sealed on the outer vertical surface. Using a centrifuge, these cores produced 43%, 33% and 42% in waterflood and 40%, 28% and 24% in surfactant flood, respectively. We matched the experimental oil recoveries using two different numerical approaches: a transfer function and a 2-D finite-difference model. The results of these experiments, numerical modeling, and field observations have given us a better understanding of the mechanism of enhanced oil production in fractured carbonate reservoirs by dilute surfactant and micellar solutions. The results of this research are intended to promote field trials.

Surfactant-enhanced oil recovery (EOR) in fracture-dominated naturally fractured reservoirs (NFR) and very low-permeability Bakken type reservoirs is less known. Therefore, to predict its performance, improvement of the reservoir simulation tools is necessary to account for the surfactant flow mechanisms as much as possible. We present an improved dual-porosity (DP) numerical simulation model and algorithm in which matrix-fracture fluid transfer function was enhanced by implementing a proper viscous displacement mechanism. This mechanism was added to the existed fluid expansion, gravity drainage, and capillary pressure mechanisms. Current DP reservoir simulators generally do not account for the viscous displacement mechanism. To validate both the accuracy and efficacy of the improved model, results were compared with the results from a variable permeability-porosity, single-continuum, fine-grid model. Simulation results of improved model were in agreement with the results of the fine-grid model as the reference case. In a one-dimensional numerical model, water flood cumulative oil production increased about 5% compared to the conventional DP model. Also, incremental oil production increased over 5% for 1 to 2 wt% surfactant concentrations. Similar results were obtained in multi-dimensional numerical models. In a representative matrix block, the water flood oil production rate started at 0.25 bbl/day in improved model compared to 0.053 bbl/day in conventional DP model. This rate was 0.124 bbl/day versus 0.03 bbl/day at the start of chemical injection. The improved model is computationally very efficient and is much faster than the fine-grid model. For a practical application, the improved model was used to design and assess the viability of an EOR pilot-test using a single-well, multiple-completion protocol in a fractured carbonate reservoir. This reservoir has a matrix permeability of 10 md and matrix porosity of 0.05, and fracture permeability of 10,000 md. Similar result was obtained using improved and fine-grid models. Also sensitivity analysis was performed on fracture spacing of 5 to 20 ft. We found that smaller matrix blocks are affected more by viscous displacement.

We use a three-dimensional random pore-scale network model to simulate gas injection into oil and water after primary drainage. The model is based on the physics of multiphase flow observed in micromodel experiments. Important features of immiscible fluid flow at the pore scale, such as wetting and spreading layers and wettability alteration are implemented. The pore network simulator is utilized to model relative permeabilities, saturation paths, and capillary pressures. A random network that represents the pore space in Berea sandstone is used in this study. Three-phase relative permeabilities generated by the network model are dependent on the saturation path, which is not known a priori. This paper includes numerical and analytical solutions for a series of secondary gas-floods with relative permeabilities generated using the network model. Analytical and simulated solutions such as these illuminate the large impact of correctly accounting for the effects of saturation history in relative permeabilities in gas injection. This knowledge is critical for the design of EOR schemes such as tertiary gas injection and WAG flooding. It is demonstrated that saturation history has a substantial impact on the relative permeabilities, and hence oil recovery. For the examples studied here, the physically-based relative permeabilities with correct saturation history exhibit an extremely rare solution structure. This is a strong indication that many of the complex solution structures frequently encountered in analytical solutions for three-phase flow may be the consequence of permeability models with little or no physical basis. To the best of our knowledge, this is the first study to per-form an analysis of the effect of physically-based relative permeabilities, using a description of the pore space and its connectivity that mimics real systems, on the saturation paths and secondary oil recovery by immiscible gas injection. Introduction Development decisions for oil fields are based on predictions of oil recovery under different putative development strategies, many of which are three-phase flow processes. These predictions use numerical simulation of multiphase fluid flow through a geological description of the reservoir. There has been an explosion of interest in assigning distributions of static properties - such as porosity and permeability - that faithfully represent the expected spatial heterogeneity and are consistent with a variety of different measurements of reservoir properties. In comparison, multiphase properties, particularly relative permeability, are given less attention, and a single set of relative permeabilities is often assigned to a given rock type, or even to the whole field. For many improved oil recovery projects, accurate estimates of relative permeabilities are crucial, particularly for flow at low oil saturations in mixed-wet reservoirs and during reservoir blow-down and gas injection, where estimates of the oil relative permeability, that has a direct relation to recovery rate, may vary by orders of magnitude. Assigning a single relative permeability to whole regions of the field based on scant core data, or an empirical model [1, 2] with a shaky physical basis, may lead to errors comparable with mistaking or ignoring the gross-scale geological heterogeneity of the field. Measurements of relative permeability are costly and time consuming and at low saturation the results are very uncertain [3, 4]. Furthermore, two independent fluid saturations are required to define a three-phase system and there is an infinite number of possible fluid arrangements, making a comprehensive suite of experimental measurements for all three-phase displacements impossible. This is mainly because the saturation path for a given grid block of the reservoir, for the process of interest, is not known a priori. In addition, the experiments are only performed on a small number of core samples, and thus cannot reproduce a representative variability in properties across the field. This is why numerical simulations of three-phase flow almost always rely on available empirical correlations to predict three-phase relative permeabilities from measured two-phase properties [1–2,5–6], despite the fact that they have little or no physical basis. The uncertainties associated with assigning multiphase flow properties often means that improved oil recovery projects are not carried out, with lost opportunity costs that may be hundreds of millions of dollars for a single field. This indicates that it is important to have a reliable physically-based tool that can provide plausible estimates of macroscopic properties.